Partial conversion hydrocracking process and apparatus

ABSTRACT

Partial conversion hydrocracking process comprising the steps of
     (a) hydrotreating a hydrocarbon feedstock with a hydrogen-rich gas to produce a hydrotreated effluent stream comprising a liquid/vapour mixture and separating the liquid/vapour mixture into a liquid phase and a vapour phase, and   (b) separating the liquid phase into a controlled liquid portion and an excess liquid portion, and   (c) combining the vapour phase with the excess liquid portion to form a vapour plus liquid portion, and   (d) separating an FCC feed-containing fraction from the controlled liquid portion and simultaneously hydrocracking the vapour plus liquid portion to produce a diesel-containing fraction, or
 
hydrocracking the controlled liquid portion to produce a diesel-containing fraction and simultaneously separating a FCC feed-containing fraction from the vapour plus liquid portion.
   

     The invention also includes an apparatus for carrying out the partial conversion hydrocracking process.

The invention relates to a partial conversion hydrocracking process andapparatus whereby heavy petroleum feed is hydrotreated and partiallyconverted to produce feed for a fluid catalytic cracking (FCC) unit. Theinvention is particularly useful in the production of ultra low sulfurdiesel (ULSD) and high quality FCC feed, which can be used to produceultra low sulfur gasoline (USLG) in the FCC unit without post treatingthe FCC gasoline to meet sulfur specifications.

BACKGROUND OF THE INVENTION

Partial conversion or “Mild” hydrocracking has been utilized by refinersfor many years to produce incremental middle distillate yields whileupgrading feedstock for fluid catalytic cracking (FCC). Initially,specialized catalysts were adapted to the low or moderate pressureconditions in FCC feed desulfurizers to achieve 20 to 30 percentconversion of heavy gas oils to diesel and lighter products. Thecombination of low pressure and high temperatures used to achievehydro-conversion conditions typically resulted in heavy, high aromaticproducts with low cetane quality. The promulgation of new specificationsfor both gasoline and diesel products has put pressure on such processesto make lighter, lower sulfur products that can fit into the refineryultra low sulfur diesel and gasoline (ULSD and ULSG) pools. Thecontinued growth in middle distillate fuel demand compared to gasolinehas re-focused attention on hydrocracking and particularly on partialconversion hydrocracking as a key process option for adapting to themodern clean fuels environment.

New specifications in both the U.S. and E.U. have mandated dramaticreductions in both diesel and gasoline sulfur levels. It is now clearthat lower sulfur levels in these products provide substantial benefitsin terms of decreased tail pipe emissions from automobiles and trucks.Pipeline transportation of both low sulfur and high sulfur distillategrades is still a work in progress. Recent studies in the U.S. indicatethat as much as 10% of ultra low sulfur diesel (ULSD) will be downgradedby common pipeline transportation, and some carriers are requiring thatULSD be no more than 5 wppm sulfur at the refinery boundary. Theenvironmental benefits and product transportation logistics make itcertain that there will be continued pressure to force all fuels intothe ultra low sulfur category.

Conventional partial conversion units utilised in many refineries aroundthe world have been designed for pressure levels in the 50 to 100 bargrange depending on feed quality and cycle life objectives. They havebeen designed to achieve 20% to 30% net conversion of heavy vacuum gasoil and total sulfur removal of about 95% to yield FCC feed suitable formaking low sulfur gasoline. The process configuration has evolved toinclude hot high pressure separators for better heat integration andamine absorbers to mitigate the effects of very high recycle gashydrogen sulfide content.

One significant shortcoming of this technology has been the inability tohave independent control of hydro-conversion and hydro-desulfurizationreaction severity. While the diesel product sulfur can be decreased to alarge extent by applying more hydrotreating catalyst and achievingdeeper HDS severity, the only real option for improving density andcetane quality is to increase reactor operating pressure or to increasehydrocracking severity.

Large increases in reactor pressure can raise chemical hydrogenconsumption by 70% to 100%. The high capital and operating costassociated with such large increases in hydrogen consumption is asignificant disadvantage for utilizing high pressure designs to achieveproduct uplift.

WO patent application No. 99/47626 discloses an integratedhydroconversion process comprising hydrocracking a combined refinery andhydrogen stream to form liquid and gaseous components. Unreactedhydrogen from the hydrocracking step is combined with a second refinerystream and hydrotreated. The product is separated into a hydrogen streamand a portion of this stream is recycled to the hydrocracking step.Higher yields of naphtha and diesel and lower yields of fuel oil wereobtained. However, this process has the disadvantage of requiring afeedstock with relatively low nitrogen, sulfur and aromatics content.This implies, in many cases, that the feedstock needs to be pre-treatedprior to the disclosed process.

U.S. Pat. No. 6,294,079 discloses an integrated low conversion processcomprising separating the effluent from a hydrotreating step into threefractions: a light fraction, an intermediate fraction and a heavyfraction. The light fraction and a portion of the intermediate and heavyfractions are bypassed the hydrocracking zone and sent to a separator. Aseries of high pressure separators are used. The remaining intermediateand heavy fractions are hydrocracked. FCC feedstock is produced. Anaugmented separator and other separators are used to separate thehydrotreater effluent into a vapour stream and two liquid streams. Partsof each liquid stream are flow controlled and remixed with the cooled,compressed vapour stream, reheated and hydrocracked at high severity toproduce the higher quality middle distillate products. The complexarrangement of multiple separators and the cooling of the vapour streamlead to the use of extra equipment and added cost.

Increasing overall hydrocracking severity is at times not a viableoption. When the process objective is to make a required amount of FCCfeed, a high conversion leads to the formation of good quality diesel.However, high conversion also results in production of insufficient FCCfeed since more diesel is produced.

The objective of this invention is to provide a process and apparatus inwhich FCC feed is treated to produce ultra low sulfur FCC feed suitablefor production of ultra low sulfur gasoline (USLG) not requiringgasoline post treatment.

Another objective of this invention is to provide a process andapparatus for producing diesel with an ultra low sulfur content andsubstantially improved ignition quality as measured by cetane number,cetane index, aromatics content and density.

A further objective of this invention is to provide a simple apparatusfor carrying out the process of the invention.

SUMMARY OF THE INVENTION

The process of the invention comprises hydrotreating and partiallyconverting a heavy petroleum feed stream which boils above 260° C. whilebeing low in asphaltenes (<0.1 wt %). By simultaneously producing highquality FCC feed the process creates the possibility of producing ultralow sulfur gasoline (USLG) from the FCC unit. Diesel and naphtha arealso produced.

The process of the invention comprises a partial conversionhydrocracking process comprising the steps of

(a) hydrotreating a hydrocarbon feedstock with a hydrogen-rich gas toproduce a hydrotreated effluent stream comprising a liquid/vapourmixture and separating the liquid/vapour mixture into a liquid phase anda vapour phase, and(b) separating the liquid phase into a controlled liquid portion and anexcess liquid portion, and(c) combining the vapour phase with the excess liquid portion to form avapour plus liquid portion, and(d) separating an FCC feed-containing fraction from the controlledliquid portion and simultaneously hydrocracking the vapour plus liquidportion to produce a diesel-containing fraction, orhydrocracking the controlled liquid portion to produce adiesel-containing fraction and simultaneously separating a FCCfeed-containing fraction from the vapour plus liquid portion.

The apparatus of the invention comprises an apparatus for the partialconversion hydrocracking process comprising a hydrotreating reactorhaving one or more catalytic beds and in series with a hydrocrackingreactor, and having an liquid/vapour separation system downstream theone or more catalytic beds of the hydrotreating reactor, theliquid/vapour separation system comprising an outlet device and anoutlet pipe in a separator vessel, the outlet device comprising a pipeextension above the bottom of the separation vessel, the pipe extensionbeing provided with an anti-swirl baffle at the top open end of the pipeextension, the separator vessel being provided with an outlet pipe atthe separator vessel bottom, the outlet pipe being provided with ananti-swirl baffle.

SUMMARY OF THE FIGURES

FIG. 1 shows a partial conversion hydrocracking process of theinvention.

FIG. 2 shows an alternative partial conversion hydrocracking process ofthe invention.

FIG. 3 shows a section through the bottom of the hydro-treatmentreactor.

FIG. 4 shows the process of the invention where the liquid/vapourseparation system is located between the hydrotreating reactor and thehydrocracking reactor.

DETAILED DESCRIPTION OF THE INVENTION

The process of the invention is a medium pressure partial conversionhydrocracking process comprising a hydrotreating step and ahydrocracking step. The process and apparatus of the invention providesa solution that meets current and expected product specifications forboth gasoline and diesel fuel without the need for further processing orblending with other lighter, higher quality components. An advantage ofthe process is that both hydrogen partial pressure and hydrocrackingconversion can be utilized for diesel quality improvement, whilemaintaining the relatively low overall conversion and HDS(hydrodesulfurization) severity requirements dictated by FCCpretreatment applications.

By the term “hydrotreating” (HDT) is meant a process carried out in thepresence of hydrogen whereby heteroatoms such as sulfur and nitrogen areremoved from hydrocarbon feedstock and the aromatic content of thehydrocarbon feed-stock is reduced. Hydrotreating covershydrodesulfurization and hydrodenitrogenation.

By the term “hydrodesulfurization” (HDS) is meant the process, wherebysulfur is removed from the hydrocarbon feed-stock.

By the term “hydrodenitrogenation” (HDN) is meant the process, wherebynitrogen is removed from the hydrocarbon feed-stock.

By the term “hydrocracking” (HC) is meant a process, whereby ahydrocarbon containing feedstock is catalytically decomposed into achemical species of smaller molecular weight in the presence ofhydrogen.

In the process of the invention the main reactor loop of the process hastwo reactors in series, a hydrotreating reactor for pretreatment of thefeedstock and a hydrocracking reactor for hydrocracking a part of theeffluent from the hydrotreating reactor. By the term “in series” ismeant the hydrocracking reactor is located downstream the hydrotreatingreactor.

There is a liquid/vapour separation system integrated in the bottom ofthe hydrotreating reactor or contained in a separator vessel locatedbetween the two reactors for separating the effluent, a mixture ofliquid and vapour, emerging from the catalytic beds of the hydrotreatingreactor.

In the liquid/vapour separation system a flash is carried out using anoutlet device and an outlet pipe. The liquid/vapour mixture separatesinto a liquid phase and a vapour phase in the separator vessel. Theoutlet device is an internal overflow standpipe for dividing the liquidphase into a controlled liquid portion and an excess liquid portion. Thevapour phase is combined with the excess liquid portion and this vapourplus liquid portion can be fed to the hydrocracking reactor. In thiscase the controlled liquid portion is withdrawn, bypassing thehydrocracking reactor and is routed to a stripper to produce FCC feedand naphtha and lighter products. It is also possible to send thecontrolled liquid portion to the hydrocracking reactor andsimultaneously separating a FCC feed-containing fraction from the vapourplus liquid portion.

By the term “flash” is meant a single stage distillation in which thehydrotreated effluent stream comprising a liquid/vapour mixture isseparated into a liquid portion and a vapour plus liquid portion. Achange in pressure is not required.

An advantage of the process of the invention is that a simple flash stepis used instead of a complex augmented and multi-separator scheme tosplit the effluent from the catalytic beds of the hydrotreating reactorinto the two portions. The vapour plus liquid portion is sent to thehydrocracking reactor without substantially cooling the vapour, otherthan the cooling required for temperature control to the inlet of thehydrocracking reactor.

Part of the liquid phase in the hydrotreater effluent is routed to anFCC feed stripper. A low pressure flash drum can optionally be added.Only naphtha and lighter hydrocarbons are recovered. The dieselcontained in this portion is of lower quality since it has a higherdensity, higher aromatic content and lower cetane value than the dieselproduced in the hydrocracking reactor, so it is better suited as an FCCfeed. The entire diesel produced by the inventive process is produced inthe hydrocracking step and have a much improved quality.

An unconverted oil that has a boiling range higher than the dieselproduct (>370° C.+) is recovered from the hydrocracked effluent in afractionator column. This is unconverted and can be used as FCC feed oras feedstock for an ethylene plant or a lube plant because it has higherhydrogen content and lower aromatic content than the FCC feed producedin the FCC feed stripper.

Suitable feedstock for the process of the invention is vacuum gas oil(VGO), heavy coker gas oil (HCGO), thermally cracked or visbroken gasoil (TCGO or VBGO) and deasphalted oil (DAO) derived from crudepetroleum or other synthetically produced hydrocarbon oil. The boilingrange of such feeds are in the range of 300° C. to 700° C. with sulfurcontent of 0.5 to 4 wt % and nitrogen content of 500 to 10,000 wppm.

The objective of the hydrotreating reactor is mainly to desulfurize thefeed down to a level of 200 to 1000 wtppm sulfur, which will result inan FCC gasoline with ultra-low sulfur content suitable for blending tomeet both European and U.S. specifications (10 and 30 wtppm,respectively), obviating the need for gasoline post-hydrotreating. Thelow sulfur content in the feed also has the benefit of dramaticallyreducing emissions of sulfur oxides (SOx) from the FCC regenerator.Secondly, the hydrotreating reactor reduces the nitrogen content in thefeed to the hydrocracking reactor. Thirdly, the aromatic content of theFCC feed is also reduced, which will result in higher conversion andhigher gasoline yields.

The hydrotreating reactor comprises a hydrotreating zone followed by aseparation zone. The hydrotreating zone contains one or more catalystbeds for hydrodesulfurization (HDS) and hydrodenitrogenation (HDN) ofthe feedstock. The products from the hydrotreating zone comprise amixture of liquid and vapour. In a conventional hydrotreating reactor,the catalyst beds are supported by bed support beams and the head spacein the bottom reactor head is filled with inert balls that support thelast catalyst bed. The mixture of vapour and liquid leaves the reactorvia an outlet collector which sits on the bottom reactor head.

In an embodiment of the inventive process, the last catalyst bed in thehydrotreating reactor is supported by bed support beams just like theupper beds. However, instead of holding a large volume of inert balls,the head space in the bottom reactor head is used to separate theliquid/vapour mixture. The liquid/vapour separation system is used inthe bottom head to split the mixture of liquid and vapour from thecatalytic beds of the hydrotreating reactor into a liquid portion and avapour portion containing a fraction of liquid, i.e. a vapour plusliquid portion.

The vapour plus liquid portion can be directed to the hydrocrackingreactor and converted under suitable conditions to produce ULSD. Thefeed to the FCC is mainly composed of the liquid portion.

The liquid/vapour separation system is integrated in the hydrotreatingreactor and located in the head space at the bottom of this reactor. Itcomprises an outlet device for transfer of the vapour plus liquidportion to the hydrocracking reactor. The liquid portion is contained inthe reactor bottom outside the outlet device and leaves thehydrotreating reactor separately through the outlet pipe for transferto, for instance, a stripper. The level of the liquid portion in thereactor bottom and hence the amount of liquid transferred to thestripper is controlled by conventional flow control valves. Excessliquid not required for transfer to the stripper thereby enters theoutlet device with all the vapour and leaves the reactor as the vapourplus liquid portion.

The amount of liquid, i.e. the controlled liquid portion, withdrawn bythe outlet pipe is set by the desired HVGO conversion. The controlledliquid portion comprises 30-100 wt % of the liquid phase, and the excessliquid portion comprises 0-70 wt % of the liquid phase. Preferably thecontrolled liquid portion comprises 60-95 wt % of the liquid phase, andthe excess liquid portion comprises 5-40 wt % of the liquid phase.

The integration of the liquid/vapour separation system in thehydrotreating reactor has the advantage of reducing the amount ofprocessing equipment when compared to conventional separation outsidethe reactor. Conventional separation outside the reactor would requireaddition of a high pressure separator vessel with the accompanyingdisadvantage of increased capital cost.

The controlled liquid portion is sent to a stripper in which a stream ofsteam removes the light hydrocarbons in the naphtha boiling range andhydrogen sulfide (H₂S) and ammonia (NH₃) dissolved in the liquid. Thestripped product is used as feed for the FCC unit. The light overheadproducts from the stripper are comprised predominantly of naphthaboiling range light hydrocarbons together with ammonia and hydrogensulfide.

All the vapour plus liquid portion leaves the separation zone of thehydrotreating reactor and is transferred to the hydrocracking reactor.The hydrocracking reactor also contains one or more catalytic beds. Thisreactor may contain some hydrotreating catalyst to further lower thenitrogen to an optimum level (<100 wppm) and a number of beds ofhydrocracking catalyst. The products from the hydrocracking reactor arecooled and transferred to an external high pressure separator vessel. Agaseous hydrogen-rich product stream is separated from the crackedproduct and recycled to the hydrotreating reactor. The liquid streamfrom the separator is sent to a distillation column where naphtha,diesel and unconverted oil products are fractionated.

Alternatively, in another embodiment of the invention, after leaving theseparation zone where the products from the hydrotreating zone are splitinto a liquid portion and a vapour plus liquid portion, the vapour plusliquid portion is directed to a separator for removal of a hydrogen-richstream. The hydrogen-rich stream can be further purified from hydrogensulfide and ammonia by amine scrubbing and water washing. The liquidproduct from the separators (a high pressure hot separator in serieswith a high pressure cold separator) is mainly FCC feed and it is sentto stripping for removal of the light hydrocarbons, H₂S and NH₃dissolved in the liquid. The stripped product is used as feed for theFCC unit.

The liquid portion from the separation zone is sent to the hydrocrackingreactor operating with a cracking severity sufficient to produce adiesel fraction with product properties in accordance with EN 590 ULSDspecifications. Operating conditions in the hydrocracking reactor can beadjusted to provide a product satisfying U.S. market requirements. Thisembodiment provides a lower ammonia and hydrogen sulfide environment inthe hydrocracking reactor which increases the hydrocracking catalystactivity.

In another embodiment of the invention, a second feed can be added asfeed to the hydrocracking reactor. In this embodiment, the second feedcan be hydrotreated and hydro-cracked in the hydrocracking reactor andbypasses the hydrotreating reactor. One example of a second feed is alight cycle oil (LCO) from the FCC, which needs further hydrotreatingand hydrocracking to convert it into high quality diesel, jet andnaphtha.

FIG. 1 illustrates an embodiment of the invention in which the vapourplus liquid portion from the separation zone is cracked in thehydrocracking reactor and the controlled liquid portion is sent to astripper.

A feed 1 is combined with hydrogen, for instance a hydrogen-rich recyclegas 2, and sent to a hydrotreating reactor 3 for hydrodesulfurizationand hydrodenitrogenation in one or more catalytic beds. The effluentfrom the one or more catalytic beds is a mixture of vapour and liquidwhich separates into a liquid phase and a vapour phase. In theseparation zone 4 downstream the last catalytic bed separation into avapour plus liquid portion 5 and a liquid portion 6 takes place using aliquid/vapour separation system integrated in the hydrotreating reactor.

The liquid/vapour separation system comprises the outlet device and theoutlet pipe (shown in FIG. 3). The liquid portion 6 consists of onlyliquid and the vapour plus liquid portion 5 includes all the vapour. Theflow rate of the liquid portion 6 is controlled by conventional flowcontrol valve 7, and excess liquid not required leaves the separationzone 4 as overflow through the outlet device together with all thevapour and thus forms the vapour plus liquid portion 5.

Controlled liquid portion 6 is comprised of heavy liquid hydrocarbonswith substantially reduced sulfur and nitrogen content relative to thefeed 1. It leaves the hydrotreating reactor 3 and bypasses thehydrocracking reactor 8 to enter a stripping column 9. Lighthydrocarbons together with ammonia and hydrogen sulfide are separatedinto the overhead stream 10 from stripping column 9 and the resultingliquid stream from the bottom of the stripping column 9 is suitable aslow sulfur FCC feed 11.

The vapour plus liquid portion 5 leaves the hydrotreating reactor 3. Itmay optionally be combined with a second hydrocarbon feedstock 22. Itthen enters the hydrocracking reactor 8 where it is catalyticallycracked to form a hydrocracked effluent 12 having properties suitablefor diesel fuel preparation. One or more catalyst beds are present inthis reactor. The hydrocracked effluent 12 is sent to a separator vessel13 and a hydrogen-rich gas stream 14 is recycled from the separator 13to the hydrotreating reactor 3 via a recycle gas compressor 15. Make-uphydrogen 16 can be added to the hydrogen-rich stream 14 either upstreamor downstream of the compressor 15 to maintain the required pressure.The liquid product 17 from the separator vessel 13 comprising light andheavy hydrocarbons together with dissolved ammonia and hydrogen sulfideis then sent to the fractionator column 18, where a naphtha stream 19with ammonia and hydrogen sulfide are removed overhead. The heavyhydrocarbon components comprising a diesel stream 20 and an unconvertedoil stream 21 are separated and recovered lower in the fractionatorcolumn 18. The naphtha stream 19 can be subjected to additionalseparation steps. The diesel stream 20 can also be further separated byboiling points into other valuable products such as aviation jet fuel.

Streams 11 (low sulfur FCC feed) and 21 (unconverted oil stream) aretypically combined as a single feed for the FCC unit. However, stream 21can also be kept segregated for use as a valuable intermediate productfor making lubricating oils or as feed for making ethylene.

Separating the liquid phase into a controlled liquid portion and anexcess liquid portion makes it possible to bypass the controlled liquidportion around the hydrocracking reactor. This allows a high conversionin the hydrocracking reactor and this improves the diesel quality whilemaintaining a low overall conversion so the desired amount of FCC feedis produced.

FIG. 2 illustrates an embodiment of the invention in which the liquidportion from the separation zone is cracked in the hydrocracking reactorand the vapour plus liquid portion is sent to the stripper column.

A feed 1 is combined with hydrogen, for instance hydrogen rich recyclegas 2, and sent to a hydrotreating reactor 3 for hydrodesulfurizationand hydrodenitrogenation in the one or more catalytic beds. Thehydrotreated effluent stream comprising a liquid/vapour mixture entersthe separation zone 4 downstream the last catalytic bed and is separatedinto a vapour plus liquid portion 5 and a controlled liquid portion 6using the outlet device as described in FIG. 1. The flow rate ofcontrolled liquid portion 6 is controlled by conventional flow controlvalve 7, and excess liquid not required leaves the separation zone 4 asoverflow through the outlet device (shown in FIG. 3) together with allthe vapour and thus forms the vapour plus liquid portion 5.

The vapour plus liquid portion 5 leaves the hydrotreating reactor 3 andflow to a separator vessel 8. A hydrogen-rich vapour stream 9 isproduced from the separator overhead and a hydrocarbon liquid stream 10is produced from the bottom of separator vessel 8. The hydrocarbonliquid stream 10 also contains dissolved ammonia and hydrogen sulfideand flows to the stripper column 11. A light hydrocarbons stream 12together with ammonia and hydrogen sulfide are separated from strippercolumn 11 and the resulting liquid stream from the bottom of strippercolumn 11 is suitable as low sulfur FCC feed 13.

Controlled liquid portion 6 is comprised of heavy liquid hydrocarbonswith substantially reduced sulfur and nitrogen content relative to thefeed 1. It leaves the hydrotreating reactor through the flow controlvalve 7 and combines with hydrogen-rich vapour stream 9 from separatorvessel 8 to make the mixed vapour-liquid stream 14. A second hydrocarbonfeedstock 26 can optionally be added to the mixed vapour-liquid stream14 if required. The mixed vapour-liquid stream 14, optionally combinedwith the second feed, enters the hydrocracking reactor 8, where it iscatalytically cracked into the components of stream 16 having propertiessuitable for diesel fuel preparation. One or more catalyst beds arepresent in reactor 15. Stream 16 flows to separator vessel 17 where ahydrogen rich vapour stream 18 is separated overhead and recycled to thehydrotreating reactor via a recycle compressor 19. Make-up hydrogen 20can be added to the hydrogen-rich stream 18 either upstream ordownstream of the compressor 19 to maintain the required pressure.

The liquid product 21 from the separator 17 comprising light and heavyhydrocarbons together with dissolved ammonia and hydrogen sulfide isthen sent to the fractionator column 22, where naphtha with ammonia andhydrogen sulfide are removed overhead in naphtha stream 23. The heavyhydrocarbon components comprising a diesel stream 24 and an unconvertedoil stream 25 are separated and recovered lower in the fractionatorcolumn 22. Naphtha stream 23 can be subjected to additional separationsteps. Diesel stream 24 can also be further separated by boiling pointsinto other valuable products such as aviation jet fuel.

FIG. 3 shows an embodiment of the invention in which the bottom sectionof the hydrotreating reactor is adapted to include the liquid/vapourseparation system. The separator vessel is therefore integrated in thebottom section of the hydrotreating reactor. The outlet device islocated below the support of the last catalyst bed 1 and the support cantypically be provided by beams and grids 2. A disengagement space 3 iscreated in the bottom of the reactor vessel to allow separation ofvapour and liquid phases.

In this embodiment of the invention the outlet device is in the form ofa standpipe 4 provided with an anti-swirl baffle 5 at the top open endof the standpipe 4. A liquid interface level 6 is created at the heightof the baffle 5 which allows all the reactor vapour and a portion of theliquid phase to overflow as a vapour plus liquid portion and exit thereactor through transfer pipe 7 to the down-stream hydrocracking reactor(not shown).

An outlet pipe 8 is provided for removing a controlled portion of theliquid phase from the centre low point of the bottom head of the reactoralso covered by an anti-swirl baffle 5. The flow of the liquid portionthrough outlet pipe 8 is regulated by the flow control element 9 througha standard flow control valve 10 through the transfer pipe 11 to adownstream stripper (not shown).

FIG. 4 illustrates another embodiment of the invention where a separatorvessel 13 containing the outlet device and the outlet pipe is addeddownstream of the hydrotreating reactor. The separator vessel 13 isconnected by pipe 12 transferring all of the vapour and liquid contentsfrom the bottom catalyst bed 1 of the hydrotreating reactor to theseparator vessel 13. In this embodiment the outlet device is in the formof a standpipe 4 provided with an anti-swirl baffle 5 at the top openend of the pipe. A liquid interface level 6 is created at the height ofthe baffle 5 which allows all the reactor vapour and a portion of theliquid phase, i.e. the vapour plus liquid portion, to overflow and exitthe hydrotreating reactor through transfer pipe 7 to the downstreamhydrocracking reactor (not shown). An outlet pipe 8 is provided forremoving a portion of the liquid phase, i.e. the controlled liquidportion, from the centre low point of the bottom head of the reactoralso covered by an anti-swirl baffle 5. The flow through this pipe isregulated by the flow control element 9 through a standard flow controlvalve 10 through the transfer pipe 11 to a downstream stripper (notshown).

This embodiment of the invention is especially advantageous whenexisting plants have to be revamped. In such cases it may not bepossible to install the liquid/vapour separation system in an alreadyexisting hydrotreating reactor. Installing the liquid/vapour separationsystem outside the hydrotreating reactor in the form of a separatorvessel containing the outlet device and the outlet pipe directlydownstream the hydrotreating reactor allows a separation of the mixtureof vapour and liquid effluent from the hydrotreating reactor into aliquid stream and a vapour plus liquid stream suitable for furtherprocessing.

The effluent from the one or more catalytic beds in the hydrotreatingreactor is a mixture of vapour and liquid which separates into a liquidphase and a vapour phase. The boiling range of the liquid phase isslightly lower than the boiling range of the feed entering thehydrotreating reactor. The liquid phase has a boiling range of 200-580°C.

Partial conversion hydrocracking catalysts useful in the process of theinvention need to fulfil the following key functional requirements:

-   -   Size and activity grading to minimize fouling and pressure drop    -   Demetallization and carbon residue reduction    -   Hydrodesulfurization for FCC feed pre-treatment to sulfur levels        of typically 100 to 1000 wppm    -   Hydrodenitrogentation for hydrocracker feed pre-treatment to        nitrogen levels of typically 50 to 100 wppm    -   Hydrocracking with high conversion activity and high selectivity        to diesel.

In order to maximize performance in each of these functional categories,stacked (multiple) catalyst systems are useful and provide betteroverall performance and lower cost compared with single multi-functioncatalyst systems. The process described here is useful in facilitatingthe independent control of reaction severity for multiple catalystsleading to optimized performance and longer useful life.

Hydrotreating catalysts are individually specified to optimize sulfurremoval for FCC feed pretreatment and for nitrogen removal forhydrocracking feed pretreatment. Zeolitic and amorphous silica-aluminahydrocracking catalysts are also useful in the process of the inventionto convert heavy feed to lighter products with high diesel yield.

The hydrotreating catalysts can for instance be based on cobalt,molybdenum, nickel and wolfram (tungsten) combinations such as CoMo,NiMo, NiCoMo and NiW and supported on suitable carriers. Examples ofsuch catalysts are TK-558, TK-559 and TK-565 from Haldor Topsøe A/S.Suitable carrier materials are silica, alumina, silica-alumina, titaniaand other support materials known in the art. Other components may beincluded in the catalyst for instance phosphorous.

Hydrocracking catalysts may include an amorphous cracking componentand/or a zeolite such as zeolite Y, ultrastable zeolite Y, dealuminatedzeolites etc. Included can also be nickel and/or cobalt and molybdenumand/or wolfram combinations. Examples are TK-931, TK-941 and TK-951 fromHaldor Topsøe A/S. The hydrocracking catalysts are also supported bysuitable carriers such as silica, alumina, silica-alumina, titania andother conventional carriers known in the art. Other components may beincluded such as phosphorus may be included as reactivity promoters.

Reaction conditions in the hydrotreating reactor include a reactortemperature between 325° C.-425° C., a liquid hourly space velocity(LHSV) in the range 0.3 hr⁻¹ to 3.0 hr⁻¹, a gas/oil ratio of 500-1,000Nm³/m³ and a reactor pressure of 80-140 bars.

Reaction conditions in the hydrocracking reactor include a reactortemperature between 325° C.-425° C., a liquid hourly space velocity(LHSV) in the range 0.3 hr⁻¹ to 3.0 hr⁻¹, a gas/oil ratio of 500-1,500Nm³/m³ and a reactor pressure of 80-140 bars.

The controlled liquid portion can comprise 30-100 wt % of the liquidphase, and the excess liquid portion can comprise 0-70 wt % of theliquid phase. Preferably the controlled liquid portion comprises 60-95wt % of the liquid phase, and the excess liquid portion comprises 5-40wt % of the liquid phase.

The current European standard EN 590 EU ULSD specifications for dieselare:

Sulfur: 10-50 wppmDensity: <845 kg/m³

T95 (D-86): <360° C.

Cetane No. D-630: >51

Cetane Index D-4737: >46 Poly-Aromatics: <11% wt.

The current U.S. standard specifications are less restrictive than theEuropean Standard specifications mentioned above.

Yield terms are defined with respect to true boiling point (TBP) cutsand the following definitions are used in the examples:

Component: TBP Cut Naphtha: <150° C. Kerosene: 150-260° C.

Heavy diesel: 260-390° C.Full range diesel: 150-390° C.

Unconverted: >390° C.

Conversion terms are defined are defined in the following, Feed andproduct values are in %:

390° C.+net conversion=Feed_(390° C.+)−Product_(390° C.+)390° C.+true conversion=(Feed_(390° C.+) _(−Product)_(390° C.+))/Feed_(390° C.+)390° C.+gross conversion=100−Product_(390° C.+)

EXAMPLES Example 1

In this example the liquid/vapour separation system is integrated in thehydrotreating reactor. This example shows how the different boilingranges of the hydrotreating reactor effluent split in the flash at theoutlet device and the outlet pipe in the liquid/vapour separationsystem.

Temperature and pressure of the hydrotreating reactor is shown atstart-of-run conditions in Table 1 and end-of-run conditions in Table 2.

TABLE 1 Naphtha Jet Diesel Gas Oil (C5-150° C.) (150-260° C.) (260-390°C.) (390° C.+) Wt % in 73.9 58.4 23.8 5.2 vapour phase Wt % in 26.1 41.676.2 94.8 liquid phase Press = 87.5 bar g Temp = 396° C.

TABLE 2 Naphtha Jet Diesel Gas Oil (C5-150° C.) (150-260° C.) (260-390°C.) (390° C.+) Wt % in 83.4 73.7 44.9 17.8 vapour phase Wt % in 16.726.3 55.1 82.2 liquid phase Press = 87.5 bar g Temp = 430° C.

The results show that the liquid phase contains mainly gas oil boilingrange material with some diesel material, but only a small portion ofjet and naphtha. The diesel boiling range material from thehydrotreating reactor has a relatively high sulfur content and highdensity, and it contains a high content of mono-aromatics so it is moresuitable as an FCC feed rather than as high quality ULSD.

The process of the invention leads to substantial economic benefits asillustrated in Table 2.

Example 2 Comparative

This example shows how the 260-390° C. diesel quality improves withadditional hydrocracking when compared to only hydrotreating a HVGO. Theresults are shown in Table 3. The 260-390° C. diesel is produced at 80bar hydrogen pressure.

TABLE 3 Hydrotreater 37% conversion 66% conversion Properties Effluentin hydrocracker in hydrocracker Sulfur, wppm 45 <10 <10 Specific 0.890gravity Cetane Index 44.6 0.881 0.860 D-976 Total Aromatics, 46.2 40.031.6 wt %

The results in Table 3 show that the qualities of an HVGO improve withconversion, as the specific gravity decreases and the cetane indexincreases.

Example 3 Comparative

This example illustrates a simplified comparison of both a conventionalmedium pressure hydrocracking process and a high pressure hydrocrackingprocess using a conventional hydrocracker as compared with the processof the invention, i.e. a medium pressure partial conversionhydrocracking process. The same pressure level was used in both the MHCand the process of the invention. Sufficient catalyst was used toachieve ULSD sulfur level (10 wppm). Table 4 shows the performance thatcan be achieved by the process of the invention.

TABLE 4 Medium Partial pressure pressure Inventive Process type HC HCprocess Reactor Pressure, barg 100 160 100 Gross Conversion⁽¹⁾, % vol.30 30 30 Diesel⁽²⁾ Yield, % vol. 31.0 31.5 28.0 Diesel Sulfur, wppm 1010 10 Diesel Density, kg/m³ 875 845 845 Cetane Index, D-4737 46 52 47Total Installed Cost⁽³⁾ 1.0 1.3 1.1 Hydrogen Demand 1.0 1.8 1.3 ⁽¹⁾100minus volume percent of fractionator bottoms FCC feed ⁽²⁾Full rangediesel cut, 150-360° C. TBP (true boiling point) ⁽³⁾Cost relative to themedium pressure HC unit (not including hydrogen generation).

The results shown in Table 4 indicate that it is not possible for a MHCprocess to make the equivalent diesel density and cetane quality ascompared to the process of the invention. Increasing hydrogen pressureto achieve sufficient aromatic saturation to match the diesel densityachieved with the invention requires about 60% higher operating pressurefor the conventional hydrocracker unit as shown by the results in Table4.

For a unit processing 5000 tonnes per day of total charge, it isestimated that the process of the invention can save 10 to 20 millionEuro capital cost compared to a high pressure conventional once-throughpartial conversion hydrocracker making the same product quality.Hydrogen is also used more efficiently using the apparatus of theinvention resulting in a savings of 250,000 normal cubic meters ofhydrogen per day. The annual operating cost savings based hydrogendemand would be 2 to 3 million euro. Utility costs are lowered relativeto the high pressure hydrocracker option, mainly as a result ofdecreased hydrogen makeup and recycle compression requirements.

1. Partial conversion hydrocracking process comprising the steps of (a) hydrotreating a hydrocarbon feedstock with a hydrogen-rich gas to produce a hydrotreated effluent stream comprising a liquid/vapour mixture and separating the liquid/vapour mixture into a liquid phase and a vapour phase, and (b) separating the liquid phase into a controlled liquid portion and an excess liquid portion, and (c) combining the vapour phase with the excess liquid portion to form a vapour plus liquid portion, and (d) separating an FCC feed-containing fraction from the controlled liquid portion and simultaneously hydrocracking the vapour plus liquid portion to produce a diesel-containing fraction, or hydrocracking the controlled liquid portion to produce a diesel-containing fraction and simultaneously separating a FCC feed-containing fraction from the vapour plus liquid portion.
 2. Process according to claim 1, wherein either the vapour plus liquid portion or the controlled liquid portion is combined with a second hydrocarbon feedstock to provide a feed for the hydrocracking step.
 3. Process according to claim 1, wherein the controlled liquid portion is hydrocracked to produce a diesel-containing fraction and the FCC feed-containing fraction is separated from the vapour plus liquid portion by cooling, washing and phase separation into a hydrogen-rich vapour stream low in ammonia and hydrogen sulfide and a hydrocarbon liquid stream comprising the FCC feed-containing fraction.
 4. Process according to claim 3, wherein the hydrogen-rich vapour stream low in ammonia and hydrogen sulfide is combined with the controlled liquid portion and hydrocracked to produce a diesel-containing fraction.
 5. Process according to claim 1, wherein the FCC feed-containing fraction is separated from the controlled liquid portion by stripping.
 6. Process according to claim 3, wherein the FCC feed-containing fraction is separated from the hydrocarbon liquid stream comprising the FCC feed-containing fraction by stripping. 7-10. (canceled) 